Tuesday, June 16, 2020

Reentry Drilling Gives New Life to Aging Fields

A recent burst of technical creativity has produced an abundance of new ways to revitalize old fields and tap bypassed pockets of oil and gas However, identifying the best solutions requires a team of experts with a broad range of skills that cross the traditional boundaries of petroleum engineering disciplines.

Over the last ten years, new technologies and field strategies have converged, enabling operators to give new life to old wells. Now, reviving production from declining fields has become a major activity for oil and gas companies, and one that requires more support to identify the right technical solutions.

Optimizing well output and economics are the key goals of these production enhancement projects and service companies are actively participating in achieving these goals.

This growing demand has pressed companies in the service sector to diversify their skills and address a wider range of reservoir and production problems. It has also stimulated a flurry of technical creativity. For example, developments in the area of reentry drilling alone- coiled tubing drilling (CTD), slimhole measurements-while-drilling (MWD) systems and new completion technologies for multiple sidetrack borehole- have produced a wealth of option for maximizing return of investment (ROI). But which approach offers the best solution; how should it be applied; and in which wells?

With this broader outlook comes an extended range of capabilities, including identifying underperforming wells and recommending cost-effective interventions to increase well productivity and maximize net present value (NPV).


Revisiting Existing Wellbores

Reentering wells to gain additional production is not new. Since the mid-1950s, oil companies have reentered old wells and drilled sidetracks to bypass formation damage or wellbore mechanical problems, and also to exploit new zones, saving the expense of drilling entirely new wells.

Recent expansion of the reentry drilling market, however, owes much to improvements in drilling and completion technology.

Reentry drilling provides a means to reduce horizontal well costs. In addition to boosting well productivity, reentry drilling can also tap bypassed reserves. Multiple lateral sidetrack can fan out from an existing wellbore for enhanced access to reservoirs.


Smaller isolated pockets of oil and gas can be tapped by extended-reach wells or multilaterals. Typically, a horizontal well will triple or quadruple productivity over a vertical well.

Today, service companies use various approaches to address the growing demand for reentry drilling. Baker Hughes INTEQ boosted its reentry drilling services with support from sistem company Baker Oil Tools, and gained a reputation as a reentry specialist in the Gulf of Mexico.














Candidates for Reentry Drilling

Fracturing, reperforating, removing damage with acid, and recompletion are all widely used methods to increase production in existing wells, thereby improving the NPV of old fields. Now, reentry drilling is generating high interest for its potential to improve recovery from damaged or depleted zones, and tap new zones at lower cost.


So when should reentry drilling be used? Many times, traditional techniques may have already been tried unsuccessfully or may not be advisable. In older wells, reentry drilling is the best option when there is an identifiable reason for a slanted or horizontal well path. Reentry drilling from an existing wellbore is less expensive than a new well. And it has the advantage that borehole trajectory through the production zone is near the original wellbore where more is known about the reservoir from cores, logs, test measurements and production history.

When the existing wellbore passes through or near a gas cap or underlying aquifer, excess gas or water production usually develops. In the absence of a gas cap, a traditional strategy to delay bottom water breakthrough is to perforate near the top of the productive interval. However, the pressure gradient due to radial flow toward the well is often sufficient to draw water upward in the shape of cone. Once water reaches the deepest perforations, it may be preferentially produced because of higher mobility.

Even in the absence of a higher mobility contact, the strong bottom waterdrive can cause excess water production. Because horizontal wells drilled near the top of an oil zone and above the oil-water contact produce a linear presssure gradient normal to the well path, bottom water will ris in the shape of a crest instead of a cone. The advancing crest-shaped water front displaces more oil than a cone shaped advance, which leadsto greater recovery by virtue of flow geometry.

In formations where sand control is required, reentry laterals may avoid the need for expensive gravel-packed completions to improve production rates while minimizing sanding problems. Compared to vertical wells, horizontal wells allow the same or higher production rates at greatly reduced drawdown pressures.

Another reason for reentry drilling is to gain better access to layered reservoirs. If individual pay zones are thick enough to be targeted by horizontal wells, multiple stacked reentry laterals are a highly effective strategy.

To balance productivity- barrels per day per unit of pressure drop - from reentry laterals, each drainhole can be drilled to an approriate length inversely proportional to the flow capacity of that particular layer.

At less cost than stacked horizontal laterals, a slanted borehole boosts productivity of layered formations. By designing wellbore trajectory with more drilled length in less-productive layers, some conformance control- balanced productivity from individual zones - can be achieved.

In some reservoirs, stratigraphic compartementalization due to depositional processes may account for bypassed hydrocarbons both vertically and horizontally. Facies with considerable contrasts in flow characteristics may serve as barriers or conduits. In some cases, reservoir sands may be too thin to be individually identified in a seismic section, but have sufficient areal extent to be visible in seismic amplitude maps for a given structural horizon. In such cases, horizontal wells may be an ideal strategy for producing thin formations and for extended reach into remote hydrocarbon sands.

A major application of horizontal wells has been in naturally fractured formations like the Austin Chalk in south Texas. When horizontal wells are drilled normal (perpendicular) to natural fracture planes, they provide an excellent plumbing system for enhancing production. Locating natural fractures and determining their orientation are crucial to getting the best well design in these formations. A horizontal well normal to natural fractures usually provides better productivity than a vertical well stimulated by hydraulic fracturing. Although natural fractures are usually vertical, shallower reservoirs and overpresured zones may have horizontal fractures open to flow. In these formations, vertical and slanted wells are reasonable choices. However, in overpressured deep formations, it may be advisable to prop the natural fractures open to avoid loss of productivity as production proceeds and pore pressure declines.

Elongated reservoirs can be the result of fluvial deposition or significant faulting. Both environments are natural candidates for horizontal drilling. In either case, there are apparent drilling strategies, depending the objective for the well. For example, wellbores can be maintained in an elongated reservoir body, or directionally drilled to encounter as many different reservoir bodies as possible. The latter case implies drilling in a normal to the elongation, which, for a fluvial reservoir, means drilling perpendicular to the downhill direction at the time of deposition.










Wednesday, June 10, 2020

Coronavirus Will Test Our New Way of Life

Constant connetivity defines 21st-century life, and the infrastructure undergirding it all is both digital (the internet and our social media platforms) and physical (the gig economy {gojek, grab, etc.} , e-commerce {tokopedia, bukalapak, etc} , global workspaces). Despite a tumultous first two decades of the century, much of our connected way of life has evaded the stress of a singular global event. The possibility of a global pandemic currently posed by the new coronavirus threatens to change that altogether. Should the virus reach the extreme levels of infection globally, it would very likely be the first true test of the 21st-century way of life, laying bare the hidden fragility of a system that has long felt seasmless.

The most obvious example is our global and connected economy, which has already weathered a deep recession. There could be shortages in crucial imports.

Worries about the future of the global economy have had interest rates headed toward to record lows while oil prices have dropped.


We design systems presuming a steady state of normalcy, but now we are about to hit this big ball of stress imminently. It will flex the system in weird ways that will cause parts to snap. And it's impossible to predict what will snap.

A global pandemic also threatens to test other systems in ways that are harder to quantify. Chief among them: our complex information ecosystem. In the event of widespread illness, we'll need to rely on accurate, vetted information to keep us safe. While the internet has made distribution easier than ever before, the democratization of information has created platforms and advertising economies built to reward misinformation.


Over the past few years, it has become clear that our social media ecosystem is easily hijacked to incentivize behaviour from the worst actors, further amplifying existing tensions and disagreements. The result? A volatile political climate, where news is weaponized for political gain- a state further exacerbated by black-box algorithms protected as corporate secrets that dictate the information we see. Their unknowable nature breeds conspirational ideas about the flow and control of information.






Tuesday, June 9, 2020

Extreme Overbalance?

In the vast majority of wells today , the moment of truth - do we have a producer, or a hole in the ground? - is revealed through underbalance perforating. When perforating guns fire, pressure in the wellbore is below that of the reservoir, creating a pressure differential that helps clean the perforation tunnels. Formation fluids rush into the tunnels and flush out metallic charge debris, surrounding crushed rock, and sands or clays that were driven into the tunnels. If the drawdown is large enough, inflow can sweep away enough debris to open the most conductive natural path between the formation and wellbore.

Two-way communication along this path is essential for optimal well completion and productivity. When a well goes straight into production, clogged perforations will limit inflow of hydrocarbons. If intervention is planned, perforations need to be clear to accept treatment fluids carrying proppant for fracturing, gravel for sand control, or acid.

Hydraulic fracturing and prepacking perforations ahead of gravel packing benefit from removal of crushed sand that can reduce injectivity and elevate fracture initiation pressures or lead to early screenout of proppant during fracture stimulations.

Underbalance perforating works across a broad range of rock properties and reservoir conditions. Its applicability decreases, however, with a decline in reservoir pressure, permeability or rock strength. The trick is to achieve enough underbalance to generate sufficient flow rate for cleaning, but not too much to collapse the perforations and drive sand into the well.

Theoretical and applied studies have focused on defining the optimal underbalance for ranges of reservoir pressure, permeability and rock strength.

With a good theoretical foundation and a record of favorable results, underbalance perforating reigned as the unchallenged champion until a few years ago, when a handful of investigators turned underbalance on its head. Building on experimental work by the US Department of Energy and others, Oryx Energy and ARCO independently developed new completion techniques utilizing extreme overbalance - perforating with wellbore pressure significantly above the level required to fracture the formation. The patented Oryx and ARCO methods differ in their approach, but each involves a process that may generically be called extreme overbalance perforating (EOP) and a related method of forcing an extreme overbalance pressure into existing perforations, called extreme overbalance surging (EOB surging).

Perforating underbalance or with extreme overbalance are in many ways opposites, but they are not mirror images of each other. In underbalance perforating, the goal is to create a channel and clean the channel with flow from the formation, then stimulate or gravel pack later as necessary. In extreme overbalance methods, the idea is to simultaneously create and stimulate the channel, which develops into a small biwing fracture that obviates the need for cleaning the perforation tunnel. Some operators have also proposed extreme overbalance methods that simultaneously place resin for sand control or acid for etching fracture faces.

Since extreme overbalance methods became commercial in 1990, their application has taken a roller coaster ride. Following an initial wave of interest, only a small but devout core of proponets continues to carry the torch- last year about half the extreme overbalance jobs in North America were performed by only five operating companies.

The EOP Why and How

John Dees and Pat Handren, extreme overbalance pioneers at the Oryx Energy began investigating overbalance methods in the late 1980s when underbalance failed to give good results in West Texas fields.

The Oryx team found what others had also observed for some time: Correctly applied underbalance perforating can be compromised by fairly common reservoir and operational conditions.

If reservoir pressure is low or depleted, the pressure differential may be insufficient to clean perforations.

Likewise, if permeability is low- probably less than 10 millidarcies (md) , but the value depends on reservoir pressure and oil viscosity- formation fluid may not flow vigorously enough for cleaning. And if rock strength is low , underbalance pressure differential large enough for effective cleaning may collapse the formation and necessitate further intervention to save the well.

Underbalance perforating can also be hindered by more complex problems. Improper killing of a well, for example, can replug perforations with filter cake that may not be dislodged during production. Sometimes, despite good reservoir pressure and permeability, the damaged zone reaches deep enough to limit the effectiveness of underbalance. Also, when permeability varies dramatically - such as thin, 1-darcy layer sandwiched between two thick 10-md layers- the thicker sections will dominate the flow properties and can reduce the effectiveness of underbalance.



Extreme overbalance perforating can sidestep these problems. In EOP completions, tubing pressure is increased before the guns are fired and then released into the wellbore with gun detonation.

At this point, because wellbore pressure exceeds rock yield strength, peforating initiates one or more small fractures. These fractures do not develop the length or height of conventional hydraulic fractures, but the event lasts long enough to push the fractures beyond the zone damaged by invasion and past the tip of the perforation. While EOP fractures are shorter in length and height, they may develop greater width and so possibly have a higher conductivity per foot than hydraulic fractures.

Most EOP jobs follow the same basic procedure. Perforating guns are lowered to the depth of interest, then spotted to the top of the guns is a small amount of liquid selected for the well conditions- brine, lease, crude, fracturing fluid, acid or liquid with proppant. All or most of the wellbore above the liquid is filled with compressible gas, usually nitrogen, less often carbon dioxide or air. The gas column is then pressured up, like a tightly squeezed coil spring. Sometimes liquid is also spotted above the gas to further compress it. Rarely does the liquid fall through the gas because compressed gas, typically at about 4000 psi [27,500 kPa], develops a density of 1 to 3 lbm/gal [0.12 to 0.36 g/cm3] and a high surface tension. This creates an interface which, in the small diameter of tubing, prevents liquid from displacing gas. Because the surface pressure of gas can reach 10,000 psi [69 Mpa] or more, tubing-conveyed perforating (TCP) guns are preferred over wireline-conveyed guns because they are operationally easier to handle at high pressures.

With detonation of the guns, the liquid is driven at very high flow rates by the rapidly expanding gas and rushes into the perforations. Because the liquid is nearly incompressible, it acts as a wedge that initiates fractures, extending the effective wellbore radius. Erosion from the liquid and any entrained proppant flowing at more than 100 bbl/min may scour the formation, creating stable flow channels. In many EOP jobs, the event is timed to stop just when the gas reaches the perforations, since the gas would quickly leak off into the formation. Some operators, who have wells with large tubular volumes, continue applying pressure as the gas enters the perforations. The gas also acts as an abrasive that scours the perforation. In either case- stopping as the gas hits the perforation or continuing - the higher the pressure and larger the gas volume ( a larger spring), the greater the fracturing power.

Pressure generated at the perforations during EOP or EOB surging must be high enough to overcome two obstacles: it must exceed the minimum in-situ rock stress, and it must fracture through any impermeable debris barrier remaining in the perforation. The debris barrier often defeats the conventional process of perforation breakdown and cleanup. Modeling shows that to overwhelm the barrier, the extreme overbalance pressure gradient usually needs to reach at least 1.4 psi per foot of well depth. This gradient produces a fracture radius that is on the order of 10 to 20 ft although it may extend up to 30 ft.

In the high-energy context of extreme overbalance, flow restriction due to perforation damage has such a minor effect on perforation conductivity as to become almost irrelevant. Charge debris has no time to harden and is thought to be pulverized and blown far back into the created cracks, like a mased up cork pushed into a wine bottle. The low permeability of the shattered zone is more than compensated for by the high permeability of the fractures. In adition,gas jetting into the tunnel at nearly the speed of sound may erode and scour walls of the tunnels and fractures.



An extension of this method involves pumping additional fluid at a high rate immediately following EOP or EOB surging, with or without proppant, to drive the fractures farther. Pump rates have to be high enough to keep the fluid above the formation fracture pressure. The injection rate needed for success depends on formation characteristics and in some cases, up to 15,000 ft3/min has been used. ARCo also developed a gas-surging technique that enhances hydraulic fracturing in wells previously perforated.

What can be expected from an extreme overbalance operation? Recoverable reserves may be increased, and under favorable conditions production rates can increase dramatically, due to reduction in near-wellbore pressure loss and in reservoir skin- 70% of EOP wells show a negative skin. In one Oyrx field, where conventionally completed wells- fracture treated with 20,000 gallons of gelled diesel and 20,000 lbm of 20/40 sand - produced 500 Mcf/D, EOP wells produced initially at twice that rate and depleted in 3 years instead of 7 to 10 years.

EOP also facilitates lower treating pressure due to creation of a more conductive flow path. In addition, EOP and EOB surging allow for placement of a higher percentage of proppant when followed by a conventional frac job. ARCO, for example, reports placement of 95% of sand in extended reach wells, probably due to higher conductivity of flow paths into the formation. It formerly placed on 35% of sand.

The economics of extreme overbalance is not clear-cut, and has contributed skepticsm. One-to-one comparison with conventional completions is sometimes difficult. Should EOP be compared to underbalance perforating alone, or to perforating and hydraulic fracturing? While the latter may seem logical, in practice EOP does not full replace hydraulic fracturing.

Some operators use EOP as a cost-effective way to identify hydraulic fracturing candidates, as a means to minimize near-wellbore tortuousity and thereby reduce hydraulic fracturing costs (less fluid pumped and lower surface pressures), or as a low-cost means to establish a high flow rate early. The biggest benefit of EOP, however, is the ability to place more sand and prevent a near-wellbore screenout during a subsequent frac job.

Costs for EOP can vary widely, and depend mostly on availability of compressed nitrogen. With easily accessible nitrogen, tublars fit for EOP pressures, and a completion that would normally include TCP guns, EOP costs slightly more than a small hydraulic fracture.

EOP can cost more than twice that of a conventional completion. While EOP wells pay out faster, with higher initial production, it remains unclear under what conditions the long-term payout from EOP is comparable to that of hydraulic fracturing.

Are EOP fractures different?

The most effective fracture, regardless of the generating mechanism, paves an autobahn between the reservoir and wellbore: a single, straigth parting of significant width with few smaller, competing fractures.




This ideal would be achieved with perforations 180 degree and aligned with the maximum in-situ stress. But this direction, called the preferred fracture plane (PFP), is often unknown, and many operators cannot yet routinely control gun orientation.

In hydraulic fracturing, pressure at the rock face rises gradually from a slight overbalance to the point of failure, after which the fracture propagates as long as the treatment continues- and it doesn't screen out or dehydrate. This gradual buildup of pressure is equivalent to opening a door by pushing it slowly. Two events probably take place. First, multiple fractures may develop from the perforation base or tip, depending on proximity of perforations to the PFP and on shot phasing.









By contrast, an EOP fracture is produced by a sudden burst of pressure. This high-rate pressurization of the rock results in a rate-dependent fracture mechanism that approaches the ideal fracture system more closely than hydraulic fracturing. Instead of opening the door by pushing gradually, an EOP operation is analogous to breaking the door down with a sledgehammer.

EOP candidates

Widely accepted candidate criteria for EOP are low permeability (below about 10 md), reservoir pressure insufficient to achieve cleaning with underbalance, a highly mobile clay content, and the need to establish a fracture in multiple layers, even those with different mechanical or flow properties.


Tubular and wellhead ratings- Tubing diameter and pressure ratings limit gas pressure and volume, which determine horsepower deliverable at the perforations. Bigger is always better, and biggest and strongest is best. At a minimum, tubing needs to endure 1.4 psi/ft. ARCO uses up to 7-in. tubing on the North Slope in Alaska, USA, and Marathon has moved from 3 1/2-in. to 4 1/2 in. tubing wherever possible.

Likewise, wellhead pressure control equipment must at least match tubular rating. The objective is to have tubulars that can safely withstand the pressures necessary to deliver a fracturing pressure at the perforations.

Perforated interval length - Dissipation of pressure over distance limits the interval length that can be effectively treated with extreme overbalance. Treatments on intervals of up to 1000 ft have been performed in a few wells, but most operators are confident that uniform, effective treatments can be carried out over only 70 to 100 ft.

Elements of EOP design: hardware

Operators recognize that success of the procedure often relies on planning completions to optimize EOP jobs. The main constraints are surface-control equipment and tubular ratings.

Downhole, Oryx will use casing with a higher pressure rating, and run cement bond logs to determine whether the interval to be perforated is full cemented. When cement bond  cannot be confirmed, Oryx prefers to keep pressure only on the tubing, using an isolation valve to avoid exceeding the casing burst rating. In addition, Oryx uses the largest possible tubing diameter to deliver the largest possible volume of gas, and always pressure tests tubing to be sure it meeets its rating.